Methods of preparing treatment fluids comprising anhydrous ammonia for use in subterranean formation operations

ABSTRACT

Methods comprising preparing a gelled fluid comprising a base fluid, a first gelling agent, and particulates; introducing the gelled fluid into a process stream, the process stream in fluid communication with a subterranean formation; introducing anhydrous ammonia into the gelled fluid at a downstream location in the process stream, thereby forming a particulate-containing treatment fluid; and introducing the particulate-containing treatment fluid into the subterranean formation from the process stream and through the wellhead.

BACKGROUND

The embodiments herein relate generally to subterranean formationoperations and, more particularly, to treatment fluids comprisinganhydrous ammonia for use in subterranean formation operations.

Subterranean formations (e.g., hydrocarbon producing wells) are oftenstimulated by hydraulic fracturing treatments. In hydraulic fracturingtreatments, a treatment fluid is pumped into a portion of a subterraneanformation at a rate and pressure such that the subterranean formationbreaks down and one or more fractures are formed. Typically, particulatesolids are then deposited in the fractures. These particulate solids(“proppant particulates” or “proppant”) serve to prevent the fracturesfrom fully closing once the hydraulic pressure is removed by forming aproppant pack. As used herein, the term “proppant pack” refers to acollection of proppant particulates in a fracture. By keeping thefracture from fully closing, the proppant particulates aid in formingconductive paths through which fluids may flow.

Subterranean formations may additionally be stimulated by acidtreatments (“acidizing”). Acidizing involves introducing an acidic fluidinto the formation to dissolve acid-soluble materials that may clog orconstrict formation channels, such as the conductive paths formedbetween proppant particulates in a proppant pack. Acidic fluids mayremove or reduce gas hydrates, among other materials, thus allowingproduced fluids from the formation to flow more readily or easilythrough the formation and into a wellbore for production. Acidizing mayalso facilitate the flow of injected treatment fluids from the wellboreinto the formation, when it is desired. In some instances, hydraulicfracturing may be performed using an acidic treatment fluid (“acidfracturing”).

Stimulation operations, and other subterranean formation operations, aredesigned to maximize production of fluids therefrom. When production isunderway, up-front costs can be recouped provided that operating costsremain low enough for the sale of oil and/or gas to be profitable.Additionally, midstream and downstream processing costs of producedhydrocarbons (i.e., oil and natural gas, which may collectively bereferred to herein simply as “oil”) may affect the profitability of theproduced hydrocarbons. Gas hydrate production in cold climates, indeepwater environments, or at any point during hydrocarbon productionmay interfere with this profitability. Gas hydrates are a form of aunique class of chemical compounds known as clathrates. Gas hydrates arecharacterized by a rigid, open network of bonded host molecules thatenclose, without direct chemical bonding, appropriately sized guestmolecules of another substance. For example, in the case of gas hydratesa crystalline water molecule acts as the host molecule, which forms a“cage” around a smaller hydrocarbon molecule (e.g., methane), therebyyielding ice-like crystals of gas and water. These gas hydrates tend toadhere to each other, resulting in large ice-like crystals formed on thesurface of hydrocarbon conduits that act as blockades (“gas hydrateplugs”).

BRIEF DESCRIPTION OF THE DRAWINGS

The following figure is included to illustrate certain aspects of theembodiments described herein, and should not be viewed as exclusiveembodiments. The subject matter disclosed is capable of considerablemodifications, alterations, combinations, and equivalents in form andfunction, as will occur to those skilled in the art and having thebenefit of this disclosure.

FIG. 1 depicts an embodiment of a system configured for deliveringvarious fluids of the embodiments described herein to a downholelocation.

DETAILED DESCRIPTION

The embodiments herein relate generally to subterranean formationoperations and, more particularly, to treatment fluids comprisinganhydrous ammonia for use in subterranean formation operations.

Current subterranean formation operations often employ large amounts ofaqueous-based treatment fluids, which may tax local resources when wateris a scarce resource, or when water desalination or other treatmentoperations are too costly or otherwise unfeasible. For example, aridregions or regions that do not have sea access may have scarce waterresources. Accordingly, subterranean formation operations in suchregions (e.g., stimulation operations, remedial operations, enhanced oilrecovery (“EOR”) operations, and the like), must compete with otherstakeholders for water use, such as agriculture, energy generation,human consumption, and the like. The concern for water scarcity insubterranean formation operations is expected to rise as such operationsare increasing in the continental United States and other arid regions,such as Western China and Australia. Accordingly, some embodimentsherein relate to subterranean formation operation treatment fluidshaving little or no water, which may be used in any region, withoutconcern for water scarcity. Nevertheless, the treatment fluids, asdescribed herein, may additionally be prepared using water or otheraqueous fluids, without departing from the scope of the presentdisclosure, and without hindering the benefits described herein.

In some embodiments, the methods and compositions described herein maybe with reference to particular subterranean formation operations (e.g.,hydraulic fracturing operations, gas hydrate removal operations,acidizing operations, and the like). However, the anhydrous ammoniatreatment fluids described herein may be used in any subterraneanformation operation that may benefit their advantages described herein,including their ability to be used in treatment fluids with little or nowater component. Such subterranean formation operations may include, butare not limited to, a drilling operation, a stimulation operation, anacidizing operation, an acid-fracturing operation, a sand controloperation, a fracturing operation, a frac-packing operation, agravel-packing operation, a production operation, a remedial operation,a gas hydrate removal operation, an enhanced oil recovery operation, aninjection operation, a pipeline operation (e.g., transportinghydrocarbon fluids through a pipeline), a remedial operation, aformation damage reduction operation, a cementing operation, and thelike, and any combination thereof.

One or more illustrative embodiments disclosed herein are presentedbelow. Not all features of an actual implementation are described orshown in this application for the sake of clarity. It is understood thatin the development of an actual embodiment incorporating the embodimentsdisclosed herein, numerous implementation-specific decisions must bemade to achieve the developer's goals, such as compliance withsystem-related, lithology-related, business-related, government-related,and other constraints, which vary by implementation and from time totime. While a developer's efforts might be complex and time-consuming,such efforts would be, nevertheless, a routine undertaking for those ofordinary skill in the art having benefit of this disclosure.

It should be noted that when “about” is provided herein at the beginningof a numerical list, the term modifies each number of the numericallist. In some numerical listings of ranges, some lower limits listed maybe greater than some upper limits listed. One skilled in the art willrecognize that the selected subset will require the selection of anupper limit in excess of the selected lower limit. Unless otherwiseindicated, all numbers expressing quantities of ingredients, propertiessuch as molecular weight, reaction conditions, and so forth used in thepresent specification and associated claims are to be understood asbeing modified in all instances by the term “about.”

Values expressed in a range format should be interpreted in a flexiblemanner to include not only the numerical values explicitly recited asthe limits of the range, but also to include all the individualnumerical values or sub-ranges encompassed within that range as if eachnumerical value and sub-range is explicitly recited. For example, arange of “about 0.1% to about 5%” or “about 0.1% to 5%” should beinterpreted to include not just about 0.1% to about 5%, but also theindividual values (e.g., 1%, 2%, 3%, and 4%) and the sub-ranges (e.g.,0.1% to 0.5%, 1.1% to 2.2%, 3.3% to 4.4%) within the indicated range.The statement “about X to Y” has the same meaning as “about X to aboutY,” unless indicated otherwise. Likewise, the statement “about X, Y, orabout Z” has the same meaning as “about X, about Y, or about Z,” unlessindicated otherwise.

The term “about” may refer to a +/−5% numerical range.

Accordingly, unless indicated to the contrary, the numerical parametersset forth in the following specification and attached claims areapproximations that may vary depending upon the desired propertiessought to be obtained by the exemplary embodiments described herein. Atthe very least, and not as an attempt to limit the application of thedoctrine of equivalents to the scope of the claim, each numericalparameter should at least be construed in light of the number ofreported significant digits and by applying ordinary roundingtechniques.

It should further be noted that, as used herein, the term“substantially” means largely, but not necessarily wholly.

While compositions and methods are described herein in terms of“comprising” various components or steps, the compositions and methodscan also “consist essentially of” or “consist of” the various componentsand steps. When “comprising” is used in a claim, it is open-ended.

In some embodiments, the present disclosure provides a treatment fluidcomprising anhydrous ammonia (“AA”) alone or in a base fluid forintroduction in a subterranean formation to perform subterraneanformation operations. That is, the AA may be sole component of thetreatment fluid, or may be in a solution, mixture, or slurry, withoutdeparting from the scope of the present disclosure. The AA may also be afoam, or a meso-solid, such as a surfactant-ammonia blend. In someembodiments, the AA in an AA treatment fluid may be in a liquid phase, agaseous phase, a supercritical phase, and any combination thereof,without departing from the scope of the present disclosure, and maydepend on a number of factors such as pressure, temperature, percentconcentration, and the like. As used herein, the term “AA treatmentfluid” will be used to describe any type or form of treatment fluidcomprising AA.

In some embodiments, the AA treatment fluids described herein may beused as an alternative to water or other base fluids for both fracturingoperations, as well as secondary treatment operations of the formation.The AA, in some embodiments, may be readily generated by the Haberprocess, which generates the AA by a reaction of nitrogen gas andhydrogen gas. In some instances, natural gas may be used as the sourcefor the hydrogen gas and air may be used as the source for the nitrogengas, both readily available in arid regions, as well as other regions.The ease of generation of AA through the Haber process, for example, maypermit such generation to occur at a well site or locationgeographically close thereto. Such generation may additionally beachieved at another location off site, without regard to the well sitelocation, without departing from the scope of the present disclosure.Moreover, the generation of AA may be relatively low in cost, and may beparticularly beneficial where the cost of water exceeds the cost ofgenerating the AA or where local legislation prohibits water use (orlarge amounts of water use).

The use of AA as a treatment fluid or as a bulk amount of a treatmentfluid may have a number of beneficial uses in a subterranean formationoperation, each of which may improve production of a formation andextend the lifetime of a formation. As used herein, the term “bulkamount of AA,” and grammatical variants thereof, refers to the AA beingpresent in a treatment fluid in the greatest weight percent of eachindividual fluid portion thereof, which may be in a liquid phase and/ora gaseous phase, but not less than about 10% of the total weight percentof the fluid portion of the treatment fluid. In other instances, the AAbeing present in a treatment fluid in an amount not less than about 20%of the total weight percent of the fluid portion of the treatment fluid.In other instances, the AA being present in a treatment fluid in anamount not less than about 33% of the total weight percent of the fluidportion of the treatment fluid. In some instances, the AA is 100% of thefluid portion of the treatment fluid. By way of example, for aliquid-only fluid having 5 individual fluid components each at a knownweight percent of the total fluid, it may be as follows: B=25% C=1%D=15%, E=10%, AA=49%. Or, for a three-component fluid the percentagesmay be B=33%, C=33%, AA=34%. In any event, the percent of AA must be thegreatest weight percentage. For an example wherein the fluid has both agas phase and a liquid phase, the AA again must be in the greatestweight percentage overall—considering the totals of the gaseous andliquid phases together.

AA may be particularly effective at at least partially inhibiting gashydrate formation in a subterranean formation, such as after astimulation operation (e.g., a fracturing operation), or in a pipelineduring transport of produced hydrocarbon fluids. That is, the AAtreatment fluid may be introduced into a formation or pipeline to atleast partially inhibit gas hydrate formation (e.g., by inhibitingformation or by reducing the presence of already formed gas hydrates).In other embodiments, the AA treatment fluid may be used to pre-treat apipeline conduit prior to flowing a hydrocarbon through the pre-treatedpipeline conduit to at least partially inhibit the formation of a gashydrate therein. As used herein, the term “at least partially inhibitingthe formation of a gas hydrate” (or “at least partially inhibiting gashydrate formation”) refers to a reduction of gas hydrate formationcompared to such formation without treatment with an AA treatment fluidsufficient to maintain a pipeline or subterranean formation (e.g., awellbore) operable.

Gas hydrates may traditionally be prevented or treated after formationwith anti-agglomerate surfactants, which operate under certainconditions. Such traditional operations may be costly and, particularlywhen determining the optimal type and concentration of surfactant touse, and typically require secondary operations to be performed inaddition to the subterranean formation operation. The AA treatmentfluids described herein, however, may be used synergistically to performa given subterranean formation operation (e.g., fracturing) whilesimultaneously controlling gas hydrate formation. They may also be usedto flow through a pipeline prior to introducing a produced hydrocarbonfluid to prevent or reduce gas hydrate formation.

The AA may form a gas at reservoir conditions, which may functionsimilar to highly diluted methane and result in a significant decreasein gas hydrate formation tendency. The AA may cause this decrease byincreasing the pressure needed for gas hydrate formation to occur.Moreover, the amount of AA required to inhibit gas hydrate formation isrelatively low, which may be as low as 0.004% by weight of the AAtreatment fluid as a whole, and any greater amount, without departingfrom the scope of the present disclosure. Additionally, by merelydecreasing the temperature (e.g., refrigeration) during flowback from aformation or at a point just prior to the end of a pipeline, the AA maybe easily captured for reuse.

Indeed, the AA in an AA treatment fluids described herein may be readilyrecovered after performing a subterranean formation operation andrecycled as it is a gas at standard temperature and pressure (“STP”),including recycling at the well head itself. As used herein, the term“STP” refers to a temperature of 273 K (0° C.) and 1 standardatmospheric pressure (101.325 kilopascal). Accordingly, the AA can beeasily stripped from a produced fluid stream (e.g., by bringing themixture to STP conditions so the gas can boil off and be captured) andre-used in future subterranean formation operations or in otheroperations that are not related to the oil and gas industry. Separationat STP may be performed by temperature distillation, gas compression,and the like. The AA may be captured by any such method for laterre-use. As an example, the recycled AA may be sold as another revenuesource for use in other industries, or stored for later use. Recovery ofAA may be dependent upon a number of factors including, but not limitedto, the type of subterranean formation, operation being performedtherein, and the like.

Another advantage of the AA treatment fluids described herein is thatthe AA may be used to at least partially ammonolyze heavy aromaticcompounds which may deposit onto or into pore throats of a subterraneanformation and decrease the productivity of the formation. As usedherein, the term “ammonolyze” and grammatical variants thereof (e.g.,ammonolysis) refers to a reaction with ammonia in which a bond isbroken. Ammonolysis may be used herein to encompass both solubility(i.e., the process of incorporating a solubilizate into or ontomicelles, such as solubilizing salt in water) and solvation (i.e., theinteraction of a solute with a solvent, resulting in a reversiblechemical combination (e.g., a dissolved molecule, ion, etc.). Thus, theAA treatment fluid may be introduced into a subterranean formationcomprising such heavy aromatic compounds where the AA at least partiallyammonolyzes the heavy aromatic compounds. As used herein, the term “atleast partially ammonolyzes” (or “at least partially ammonolyzing”)refers to greater than about 10% ammonolysis.

Such heavy aromatic compounds may include, but are not limited to,kerogen, bitumen, asphaltenes, paraffins, and the like, and anycombination thereof. For example, the AA may be used to solvate anelectron taken from a Group I metal, for example. The solvated electronmay induce a charge on a molecule (e.g., a nanotube) thus disrupting theVan der Waals interactions of those molecules, allowing solvation. Indoing so, pore pathways within the formation may be opened by developingwormholes in the source rock where the heavy aromatic compounds oncewere by solvation with the AA. As used herein, the term “wormhole”refers to voids created within a subterranean formation source rock.These wormholes allow a pathway for hydrocarbons to flow from theformation and into a wellbore, which is not achieved using traditionaltreatment fluids for subterranean formation operations (e.g., hydraulicfracturing).

As discussed herein, the AA treatment fluids of the present disclosuremay be used in a variety of subterranean formation operations. Forexample, in some embodiments, the AA treatment fluids may be used in ahydraulic fracturing treatment where the AA treatment fluid isintroduced into a subterranean formation operation at a rate andpressure sufficient to create or enhance at least one fracture therein.When used in hydraulic fracturing operations, or in other operationsafter fracturing, the AA in the AA treatment fluid may also be used toetch microfractures in the formation rock. As used herein, the term“microfracture” refers to a discontinuity in a portion of a subterraneanformation (e.g., a fracture) such that an etch is created in theformation. For example, where the formation rock is shale, the AAmolecule, particularly when in the liquid phase, induced microfracturesthrough shale embrittlement due to the unique polarization of the AA.The formation may also be any other formation type having AA-solublematerials that may be removed using the AA treatment fluids describedherein to increase the surface area (e.g., wormholes) in the formation.Such microfractures may similarly be formed by the solvation and/oremulsification of heavy aromatic compounds, as previously described.These microfractures may improve a formation's production of desiredfluids (e.g., hydrocarbons).

As well as fracturing operations, other subterranean operations relatedto production, clean-up, and EOR may be enhanced by using the AAtreatment fluids described herein. In particular, temperature increasesdue to liberation of thermal energy may occur within a subterraneanformation upon contact of the AA in the AA treatment fluid with connatewater, where the AA and the connate water react to form ammoniahydroxide. As used herein, the term “connate water” refers to watertrapped in the interstices of a subterranean formation (e.g.,sedimentary rock) at the time of its deposition. The increase intemperature upon such contact may decrease the viscosity of hydrocarbons(e.g., heavy crude) within the formation, thus inhibiting the surfacetension interactions of an oil-wet surface of the formation and allowingsuch hydrocarbons to flow more easily from the pore spaces of theformation and into a wellbore. Accordingly, for example, traditionalheat EOR and the associated high costs therewith may be avoided byinducing a migrating heat front using the AA treatment fluids describedherein. This migrating heat front may be used in a targeted fashion(e.g., at a particular location in a formation), and may be particularlyuseful in multilateral well systems.

In some embodiments, the AA in any of the AA treatment fluids describedherein may be a supercritical fluid. As used herein, the term“supercritical fluid” refers to a substance (e.g., AA) at a temperatureand pressure above its critical point, where distinct liquid and gasphases do not exist. Such supercritical fluids may be able to effusethrough solids like a gas, and dissolve materials like a liquid. In someinstances, the use of supercritical AA in the AA treatment fluids may beused in lieu of traditional acid treatments, which typically employ anacid (e.g., hydrofluoric acid, hydrochloric acid, acetic acid, and thelike, and combinations thereof) to dissolve formation damage (e.g.,silicates or carbonates) to increase permeability of the formation. Theuse of supercritical AA may achieve the desired dissolution andincreased permeability without the aggressive and corrosive nature oftraditional acids that may pose a risk to the environment and/or humanhealth. That is, the AA, and at supercritical conditions, is simple,easy to use, and environmentally friendly. As used herein, the term“formation damage” refers to a reduction in the permeability of aformation (e.g., in the near wellbore region), such as by deposition ofa filtercake, natural or intentional, on the face of the formation.

The use of supercritical AA treatment fluids may further permit singleuse fluids for certain subterranean formation operations, including anyof those previously discussed (e.g., fracturing operations, productionoperations, remedial operations, EOR operations, pipeline operations,and the like). For example, the supercritical AA treatment fluids may beused as a fracturing fluid that simultaneously performs as an acidizingfluid, without having to use a two-step fluid treatment, as istraditionally done. Such is true with both primary and remedialsubterranean formation operations. The synergistic operation of thesupercritical AA treatment fluids is thus, not only environmentallyfriendly, but also economic in terms of time and cost.

Supercritical fluids, such as supercritical AA for use in the AAtreatment fluids described herein, may exhibit several advantages suchas increased solubilities, near zero surface tension, low viscosity andhigh diffusivity resulting in high mass transfer, and the like. Each ofthese advantages are extremely valuable for dissolution of otherwisedifficult to dissolve substances in a formation typically targeted byacid treatments.

Supercritical AA has the benefit of being able to solubilize heavyinsoluble compounds, such as silicon dioxide (SiO₂), with enhancedsolubilization properties (e.g., supercritical water has been shown tobe enhanced when combined with a base). AA achieves its supercriticalstatus at a temperature greater than 132.4° C. (270.3° F.) and pressuregreater than 112.8 bar (1636 pounds per square inch). Such conditionsare typical of many subterranean formations, thus naturally facilitatingthe use of AA in an AA treatment fluid at its supercritical point.

As an example, calcareous formations may comprise various alkali oralkali-earth carbonates, such as, for example, potassium carbonate,sodium carbonate, calcium carbonate, magnesium carbonate, and the likeand any combination thereof. Such calcareous formations may additionallycomprise other transition metal carbonates, such as, for example, ironcarbonate, copper carbonate, zinc carbonate, and the like, and anycombination thereof. These carbonates may react with supercritical AA inan AA treatment fluid and form either corresponding ammonium salts (andother salt formations, such as nitrate salts) or other ammonia adductsor complexes. Such ammonia adducts or complexes may be referred to asammonates or amine complexes, which may be more analogous to commonlyknown hydrates (e.g., CaCl₂×8NH₃, CuSO₄×4NH₃, and the like). Both ofthese ammonium salts and ammonium adducts or complexes are very solublein AA, particularly supercritical AA, making the AA treatment fluid atsupercritical conditions particularly effective as an alternative to anacid treatment. Accordingly, subterranean formations comprising suchalkali carbonates, alkali-earth carbonates, transition metal carbonates,and the like, and combinations thereof, may have an AA treatment fluidintroduced therein where the subterranean formation has a temperatureand pressure that meets or exceeds the supercritical point for the AA,and wherein the supercritical AA at least partially solubilizes thecarbonates.

As further example as to mechanisms of the supercritical AA's ability todissolve minerals in formations that may inhibit produced hydrocarbonflow, Mechanism I and II are provided below with reference to calcareousformations. Mechanism I demonstrates the mechanism by which thesupercritical AA generates ammonium salts from minerals present withinthe formation itself. Such ammonium salts are readily dissolvable insupercritical AA and thus can be easily removed from a formation zone ofinterest.CaCO₃+2NH₃+2H₂O→(NH₄)₂.CO₃+Ca(OH)₂  Mechanism I

Mechanism II demonstrates the mechanism by which the supercritical AAcoordinates metals found in the minerals present within the formationitself into a coordination sphere, forming the ammonia adducts orcomplexes described above, such as ammonates. Such ammonia adducts orcomplexes are readily dissolvable in supercritical AA and thus caneasily be removed from a formation zone of interest.CaCO₃ .xH₂O+nNH₃→CaCO₃ .nNH₃ +xH₂O  Mechanism IIwhere x is an integer between 1 and 6, and n is an integer between 1 and6.

The ammonium salts (and other salts such as nitrate salts) and theammonium adducts or complexes are generally environmentally friendly orbeneficial to the environment (e.g., beneficial for soil), making theuse of supercritical AA particularly valuable when compared to corrosiveacid treatments traditionally used. Indeed, AA is used as a fertilizerfor crop growth, and as compared to acid treatments, for example, itdoes not possess the corrosiveness of such fluids.

Additionally, supercritical AA used in the AA treatment fluids describedherein may reduce scale formation on equipment (e.g., pumping equipment,and the like) because it has the ability to coordinate (i.e., formcoordination spheres) with cations present within various treatmentfluids or formation fluids (e.g., water), thus generating solublecompounds that prevent or reduce the precipitation of scale formation.

In some embodiments, the AA treatment fluids of the present disclosuremay further comprise an oilfield additive. Such oilfield additives mayinclude, but are not limited to, a gelling agent, a salt, a weightingagent, an inert solid, a fluid loss control agent, an emulsifier, adispersion aid, a corrosion inhibitor, an emulsion thinner, an emulsionthickener, a surfactant, a particulate, a proppant, a gravelparticulate, a lost circulation material, a foaming agent, a gas, a pHcontrol additive, a breaker, a biocide, a crosslinker, a stabilizer, achelating agent, a scale inhibitor, a gas hydrate inhibitor, a mutualsolvent, an oxidizer, a reducer, a friction reducer, a clay stabilizingagent, a defoaming agent, and any combination thereof.

In some embodiments, the AA treatment fluid may be in a liquid phase ora supercritical phase and may be a gelled AA treatment fluid, whereinthe AA treatment fluid comprises a gelling agent, for use in any of thesubterranean operations described herein (e.g., drilling operations,fracturing operations, and the like, and combinations thereof). In someembodiments, the gelling agent in the AA treatment fluid may be acolloidal clay. The colloidal clays for use in the AA treatment fluidsmay increase viscosity, provide friction reduction, and the like. Asused herein, the term “colloidal clay” refers to a clay that forms acolloidal dispersion when mixed into a treatment fluid. As used herein,the term “colloidal dispersion” refers to a substance in whichmicroscopically dispersed insoluble particles are suspended throughoutanother substance.

In aqueous applications, the colloidal dispersion formed by thecolloidal clay may be in the shape of a “house of cards” or “sheet”structure, owed to the presence of silicate tetrahedrons in the clay, inwhich a central silicon atom is surrounded by four oxygen atoms at thecorners of the tetrahedron. The sheets are formed by the sharing ofthree of the oxygen atoms of each tetrahedron with other tetrahedronswithout any two tetrahedrons having more than one oxygen atom in common(e.g., each tetrahedron is linked to three other, distincttetrahedrons). The remaining unshared oxygen atom is capable ofinteraction or bonding with other atoms or molecules. The sheets formedfrom the colloidal clay may be characterized as having a strong negativecharge on the face of the sheet and a weak positive charge on the rim.As a result of these charges, the sheets may exhibit face-edgeaggregation, leading to the relatively open, macroporous sheetstructure.

However, not all colloidal clays are water dispersible due to smallionic interaction and interchanges within the clay. Accordingly, for usein the AA treatment fluids described herein, these small interactionsmay be broken by contact with the AA, resulting in a uniformlydistributed colloid AA-clay gelled treatment fluid. The AA may inhibitthe formation of the house-of-cards structure by the colloidal clays dueto the polarity of the ammonia disrupting the charge bonding of thecolloidal clays and inhibiting the house-of-cards structure, which maybe preferred to enhance production by having uniformly distributed clay.Such an AA gelled treatment fluid may be used in a variety ofsubterranean formation operations, including fracturing operations(e.g., for proppant suspension and transport), and the like.

In some embodiments, the colloidal clay gelling agent for use in the AAtreatment fluids described herein may include, but are not limited to, aphyllosilicate clay, a tectosillicate clay, and any combination thereof.Such colloidal clays may be anhydrous or hydrated, and naturallyoccurring or synthetic. In some instances, the colloidal clays may havevariable amounts of cations, such as sodium cations, iron cations,magnesium cations, and the like, and any combination thereof.

Suitable phyllosilicate clays for use in the AA treatment fluidsdescribed herein may include, but are not limited to, an aliettite, abeidellite, a ferrosaponite, a hectorite, a laponite, a nontronite, apimelite, a saliotite, a saponite, a sauconite, a stevensite, aswinefordite, a volkonskoite, a yakhontovite, a zincsilite, an amesite,an antigorite, a berthierine, a brindleyite, a caryopilite, achrysotile, a clinochrysotile, a cronstedtite, a dickite, a fraipontite,a greenalite, a halloysite, a kaolinite, a kellyite, a lizardite, amanandonite, a nacrite, a nepouite, an odinite, an orthochrysotile, aparachrysotile, a pecoraite, a ferripyropyllite, a minnesotaite, apyrophyllite, a talc, a willemseite, an aluminoceladonite, an anadite,an aspidolite, a biotite, a bityite, a boromuscovite, a celadonite, achernykhite, a chromceladonite, a clintonite, an ephesite, aferro-aluminoceladonite, a ferroceladonite, a ferrokinoshitalite, aganterite, a glauconite, a hendricksite, an illite, a kinoshitalite, alepidolite, a luanshiweiite, a margarite, a masutomilite, a montdorite,a muscovite, a nanpingite, a norrishite, an oxykinoshitalite, anoxyphlogopite, a phengite, a phlogopite, a polylithionite, apreiswerkite, a roscoelite, a shirokshinite, a siderophyllite, asokolovaite, a suhailite, a tainiolite, a tetraferriphlogopite, atovelite, a trilithionite, a voloshinite, a yangzhumingite, azinnwaldite, a baileychlore, a borocookeite, a chamosite, a clinochlore,a cookeite, a corundophilite, a donbassite, a franklinfurnaceite, animite, an orthochamosite, a pennantite, a sudoite, and the like, andany combinations thereof.

Suitable tectosilicate clays for use in the AA treatment fluidsdescribed herein may include, but are not limited to, a quartz, atridymite, a cristobalite, a coesite, a feldspar, an alkali-feldspar, amicrocline, an orthoclase, an anorthoclase, a sanidine, an albite, aplagioclase feldspar, an oligoclase, an andesine, a labradorite, abytownite, an anorthite, a felsparthoid, a norsean, a cancrinite, aleucite, a nepheline, a sodalite, a hauyne, a lazurite, a petalite, ascapolite, a marialite, a meionite, an analcime, a zeolite, a chabazite,a heulandite, a stilbite, a scolecite, a mordenite, an aluminosilicate,an andalusite, a kyanite, a sillimanite, a calcium aluminosilicate, asodium aluminosilicate, a jadeite, and the like, and any combinationthereof.

In other embodiments, the gelling agent may be a naturally-occurringgelling agent, a synthetic gelling agent, and any combination thereof.Suitable gelling agents may include, but are not limited to,polysaccharides, biopolymers, and/or derivatives thereof that containone or more of the monosaccharide units: galactose, mannose, glucoside,glucose, xylose, arabinose, fructose, glucuronic acid, and/or pyranosylsulfate. Examples of suitable polysaccharides include, but are notlimited to, guar gums (e.g., hydroxyethyl guar, hydroxypropyl guar,carboxymethyl guar, carboxymethylhydroxyethyl guar, andcarboxymethylhydroxypropyl guar), cellulose derivatives (e.g.,hydroxyethyl cellulose, carboxyethylcellulose, carboxymethylcellulose,and carboxymethylhydroxyethylcellulose), xanthan, scleroglucan,succinoglycan, diutan, and the like, and any combination thereof.

Suitable synthetic polymers may include, but are not limited to,2,2′-azobis(2,4-dimethyl valeronitrile),2,2′-azobis(2,4-dimethyl-4-methoxy valeronitrile), polymers andcopolymers of acrylamide ethyltrimethyl ammonium chloride, acrylamide,acrylamido- and methacrylamido-alkyl trialkyl ammonium salts,acrylamidomethylpropane sulfonic acid, acrylamidopropyl trimethylammonium chloride, acrylic acid, dimethylaminoethyl methacrylamide,dimethylaminoethyl methacrylate, dimethylaminopropyl methacrylamide,dimethylaminopropylmethacrylamide, dimethyldiallylammonium chloride,dimethylethyl acrylate, fumaramide, methacrylamide, methacrylamidopropyltrimethyl ammonium chloride,methacrylamidopropyldimethyl-n-dodecylammonium chloride,methacrylamidopropyldimethyl-n-octylammonium chloride,methacrylamidopropyltrimethylammonium chloride, methacryloylalkyltrialkyl ammonium salts, methacryloylethyl trimethyl ammonium chloride,methacrylylamidopropyldimethylcetylammonium chloride,N-(3-sulfopropyl)-N-methacrylamidopropyl-N,N-dimethyl ammonium betaine,N,N-dimethylacrylamide, N-methylacrylamide,nonylphenoxypoly(ethyleneoxy)ethylmethacrylate, partially hydrolyzedpolyacrylamide, poly 2-amino-2-methyl propane sulfonic acid, polyvinylalcohol, sodium 2-acrylamido-2-methylpropane sulfonate, quaternizeddimethylaminoethylacrylate, quaternized dimethylaminoethylmethacrylate,and the like, and any combination thereof. In certain embodiments, thegelling agent may comprise anacrylamide/2-(methacryloyloxy)ethyltrimethylammonium methyl sulfatecopolymer, an acrylamide/2-(methacryloyloxy)ethyltrimethylammoniumchloride copolymer, a derivatized cellulose that comprises cellulosegrafted with an allyl or a vinyl monomer, and the like, and anycombination thereof.

Additionally, polymers and copolymers that comprise one or morefunctional groups (e.g., hydroxyl, cis-hydroxyl, carboxylic acids,derivatives of carboxylic acids, sulfate, sulfonate, phosphate,phosphonate, amino, or amide groups) may be used as gelling agents.

The gelling agent (e.g., colloidal clay) may be present in the AAtreatment fluids described herein in an amount sufficient to provide thedesired viscosity and/or friction reducing properties. In someembodiments, the gelling agents may be present in the AA treatmentfluids in an amount in the range of from a lower limit of about 0.01%,0.05%, 0.1%, 0.5%, 1%, 1.5%, 2%, 2.5%, 3%, 3.5%, 4%, and 4.5% to anupper limit of about 10%, 9.5%, 9%, 8.5%, 8%, 7.5%, 7%, 6.5%, 6%, 5.5%,5%, and 4.5% by weight of the AA treatment fluid, encompassing any valueand subset therebetween.

In some embodiments, the present disclosure provides a method ofpreparing and delivering the AA treatment fluids to a downhole location.Referring now to FIG. 1, illustrated is a delivery system and method fordelivering a treatment fluid comprising AA to a downhole location,according to one or more embodiments described herein. As illustrated,FIG. 1 generally depicts a land-based system; however, it is to berecognized that like systems may be operated in subsea locations,without departing from the scope of the present disclosure.

The delivery system described herein may be in various forms, includingbatch form or continuous form. In some embodiments, a well system 1 maygenerally include a storage tank 10, in which an initial portion of thetreatment fluid described herein may be formulated. The storage tank 10may be a tanker or silo, and may additionally be equipped as a mixer,without departing from the scope of the present disclosure. Thetreatment fluid may then be conveyed via a process stream 12 in fluidcommunication with the storage tank 10 to a wellhead 14, wherein theprocess stream 12 is in fluid communication with the wellhead 10. Theprocess stream 12 may carry the treatment fluid and may be fluidlyconnected to various inputs 20,22, 24 (in phantom) for including variousfluids and/or oilfield additives into the treatment fluid, as describedin detail below. The treatment fluid may then be conveyed into asubterranean formation 18 by means of a tubular 16 in fluidcommunication with the wellhead 14 and subterranean formation 18.

A pump 26 may be configured to raise the pressure of the portion of thetreatment fluid in the process stream 12 to a desired degree before itsintroduction into the tubular 16. Generally, the pump 26 may be alow-pressure pump that operates at a pressure of about 1000 psi or less(e.g., atmospheric pressure). Depending on the nature of the deliverysystem (e.g., batch or continuous), a blender or mixer 28 (in phantom)may also be included in fluid communication with the process stream 12upstream of the storage tank 10. As used herein, the term “upstream”with reference to the process stream 12 refers to a location toward thestorage tank 10 and the term “downstream” with reference to the processstream 12 refers to a location toward the wellhead 14. Just prior tointroducing the treatment fluid into the tubular 16 through the wellhead14, a portion of the treatment fluid flows through the process stream 12and encounters a high-pressure pump 30, that elevates the pressure to apressure greater than about 1000 psi. In some embodiments, the lowpressure pump 26 may “step up” the pressure of the treatment fluidbefore it reaches the high pressure pump 30. The high pressure pumppermits AA to be added to the process stream 12 downstream thereto andinto the treatment fluid for introduction into the subterraneanformation 18 through the wellhead 14 and tubular 16.

It should be noted that while FIG. 1 is merely an illustrativeembodiment of the present disclosure and the order and number of thepumps 26,30; inlets 20,22,24; and blender(s) 28 may vary depending onthe nature of the particular embodiment employed. That is, theprocessing stream 12 may have at any location therealong any number andorder of pumps, inlets, and blends, without departing from the scope ofthe present disclosure. Moreover, the process stream 12 may furtherinclude additional components, without departing from the scope of thepresent disclosure. Non-limiting additional components that may bepresent include, but are not limited to, supply hoppers, valves,condensers, adapters, joints, gauges, sensors, compressors, pressurecontrollers, pressure sensors, flow rate controllers, flow rate sensors,temperature sensors, and the like.

Although not depicted in FIG. 1, the treatment fluid may, in someembodiments, flow back to the wellhead 14 and exit subterraneanformation 18. In some embodiments, the treatment fluid that has flowedback to wellhead 14 may subsequently be recovered and recirculated tosubterranean formation 18, or recycled as described above.

In one embodiment, the present disclosure provides a batch method ofdelivering an AA treatment fluid to a downhole location comprisingpreparing a gelled fluid comprising a base fluid, a first gelling agent,and particulates. The gelled fluid may be formulated or otherwise housedin the storage tank 10. From the storage tank 10, the gelled fluid maybe introduced into the process stream 12 by use of the low-pressure pump26. As previously discussed, the process stream 12 is in fluidcommunication with the wellhead 14 and the wellhead 14 is in fluidcommunication with the subterranean formation 18 via the tubular 16. Thegelled fluid passes the high-pressure pump 30 downstream of the storagetank 10 and thereafter AA is introduced into the gelled fluid at alocation downstream of the storage tank 10 and downstream of thehigh-pressure pump 30, thereby forming a particulate-containingtreatment fluid comprising AA. The particular-containing treatment fluidcomprising AA is then introduced into the subterranean formation 18 viathe tubular 16 through the wellhead 14. In some embodiments, oilfieldadditives, including those discussed herein, may be included in thegelled fluid in the storage tank 10 prior to entering the process stream12 or may be included in the process stream upstream of thehigh-pressure pump 30, such as through inlet 22, 24 (in phantom) and,when desired, one or more blenders 28 (in phantom) may be included tomix the components in the process stream 12 at any location downstreamof the storage tank 10 and, in most instances, upstream of thehigh-pressure pump 30.

In other embodiments, the present disclosure provides a continuousmethod of delivering an AA treatment fluid to a downhole locationcomprising preparing a gelled fluid comprising a first base fluid and afirst gelling agent. The gelled fluid may be formulated or otherwisehoused in the storage tank 10. From the storage tank 10, the gelledfluid may be introduced into the process stream 12 by use of thelow-pressure pump 26. Thereafter, particulates may be introduced intothe process stream at one or more of inlet 22 or 24 upstream of thestorage tank 10, thereby forming a particulate slurry. In someembodiments, the particulates may be introduced into the process stream12 in a gelled particulate slurry comprising a second base fluid and asecond gelling agent. The particular slurry passes the high-pressurepump 30 downstream of the storage tank 10 and thereafter AA isintroduced into the particular slurry, thereby forming aparticulate-containing treatment fluid comprising AA. Theparticulate-containing treatment fluid comprising AA is then introducedinto the subterranean formation 18 via the tubular 16 through thewellhead 14. As discussed above, oilfield additives may be included inthe initial gelled fluid or may be introduced into the process stream 12at any location, such as through inlet 22, 24 (in phantom) and, whendesired, one or more blenders 28 (in phantom) may be included at anylocation along the process stream 12.

In other embodiments, the first gelling agent may be formulated orhoused in the storage tank 10 and the base fluid and particulates may beintroduced into the process stream 12 together or separately through oneor more of inlet 20,22,24, without departing from the scope of thepresent disclosure. And if a mixer 28 is included in the process stream12, such inlets may be located either upstream or downstream of themixer 28, without departing from the scope of the present disclosure.

In some embodiments, the introduction of the particulates, the basefluid, or any oilfield additive in the process stream 12 may occursimultaneously in time with the introduction of the AA into the processstream 12 or sequentially in time, without departing from the scope ofthe present disclosure. That is, although the location of suchintroduction is different with reference to the process stream 12, itmay be simultaneous or sequential in time at those different locations.

The base fluid comprising a first gelling agent, particulates, and/orone or more oilfield additives at any location in the process stream 12prior to the addition of the AA may be used as a thick gel that carriesthose particulates and/or one or more oilfield additives in a pumpableform. However, addition of the AA serves to dilute the gel to a formreadily useable (and pumpable) at a downhole location for use in asubterranean formation operation. That is, the gel will carry desiredparticulates and/or additives throughout the process stream 12 andvarious equipment attached thereto as required for a particularoperation, which is then mixed with the AA, where the AA is safelycontained in a pressurized system and used to dilute the gel just priorto introduction of the particulate-containing treatment fluid comprisingAA into the subterranean formation 18. The particulate-containingtreatment fluid comprising AA may be introduced into the subterraneanformation 18 in the form of an emulsion (liquid phase AA), a comingledfluid, a miscible fluid, or a foamed fluid. With reference to the foamedfluid, depending on the application, the AA may be in the gas phase ofthe liquid/solid phase of the foam. For example, a CO₂/NH₃ foam may begenerated.

The treatment fluids for use in the embodiments described herein maycomprise a bulk amount of AA. As described above, the term “bulk amountof AA” refers to the AA being present in the treatment fluids describedherein in the greatest weight percent of each individual fluid portionthereof, which may be in a liquid phase and/or a gaseous phase, but notless than about 10% of the total weight percent of the fluid portion ofthe treatment fluid. Accordingly, the bulk amount of AA may be presentin a weight percent of greater than about 10%, 20%, 30%, 40%, 50%, 60%,70%, 80%, and 90%, encompassing any value and subset therebetween.Moreover, in some embodiments, the AA itself may form the entirety ofthe AA treatment fluids described herein.

In some embodiments, the treatment fluids described herein may compriseAA and a base fluid. The base fluid may include, but may not be limitedto, an aqueous base fluid, an oil base fluid, a solvent base fluid, aviscoelastic base fluid, a hydrocolloid base fluid, and the like, andany combination thereof. The base fluids may be any phase form includingliquid phase or gaseous phase (e.g., steam). In some embodiments,without limitation, the treatment fluids comprising the AA describedherein may consist essentially of a substantially non-aqueous liquidportion thereof. As used herein, the term “substantially non-aqueousliquid portion” refers to the liquid portion having no more than about1% by weight thereof being aqueous. Such substantially non-aqueousliquid portions may include, but are not limited to, the oil basefluids, the viscoelastic base fluids, and/or the hydrocolloid basefluids described herein, for example.

Suitable aqueous base fluids may include, but are not limited to, freshwater, saltwater (e.g., water containing one or more salts dissolvedtherein), brine (e.g., saturated salt water), seawater, or combinationsthereof. Generally, the water may be from any source, provided that itdoes not contain components that might adversely affect the stabilityand/or performance of the treatment fluids of the embodiments of thepresent disclosure. For example, the water may be recovered water (i.e.,water used as part of a subterranean formation operation), reclaimedwater (i.e., wastewater (sewage) that has been treated to remove certainimpurities and/or solids), and the like.

Suitable oil base fluids may include, but are not limited to, alkanes,olefins, aromatic organic compounds, cyclic alkanes, paraffins, dieselfluids, mineral oils, desulfurized hydrogenated kerosenes, and the like,and any combination thereof. Suitable solvent base fluids may include,but are not limited to, alcohols (e.g., methanol, ethanol, n-propanol,isopropanol, n-butanol, sec-butanol, isobutanol, and t-butanol),glycerins, glycols (e.g., polyglycols, propylene glycol, and ethyleneglycol), polyglycol amines, polyols, any derivative thereof, and thelike, and any combination thereof.

Suitable viscoelastic base fluids may include, but are not limited to,methyl ester sulfonates, sulfosuccinates, taurates, amine oxides,ethoxylated amides, alkoxylated fatty acids, alkoxylated alcohols (e.g.,lauryl alcohol ethoxylate, ethoxylated nonyl phenol), ethoxylated fattyamines, ethoxylated alkyl amines (e.g., cocoalkylamine ethoxylate),betaines, modified betaines, alkylamidobetaines (e.g., cocoamidopropylbetaine), quaternary ammonium compounds (e.g., trimethyltallowammoniumchloride, trimethylcocoammonium chloride), and the like, any derivativesthereof, and any combination thereof. Viscoelastic base fluids may bedescribed as having a hydrophobic tail group that is non-hydrogen bondforming with the hydrophilic head group being hydrogen bonding.Accordingly, AA may be capable of forming a hydrogen bond to formmicelles and rods with the viscoelastic base fluid, and solvating theviscoelastic base fluid, thereby being capable of, for example,obtaining sufficient viscosity to carry particulates (e.g., proppant).

Hydrocolloid base fluids may comprise a substance that can viscosify orthicken the treatment fluids of the present disclosure. In someinstances, the hydrocolloid base fluids may comprise only the substance,described below, or, in other embodiments, the hydrocolloid base fluidsmay include the substance in any one of the other base fluids describedfor use in the embodiments herein. Accordingly, the hydrocolloid basefluid may not be in the form a fluid phase until the bulk amount of AAis included to form the treatment fluid, without departing from thescope of the present disclosure.

Suitable hydrocolloid base fluids may include, but are not limited to,silicon, acrylamide-based polymers (e.g., polyacrylamide),polymethylate-based polymers, and derivatized polysaccharides, where thepolymers or polysaccharides thicken a treatment fluid, as describedherein. For example, the derivitization of the derivatizedpolysaccharides may allow the polysaccharides to thicken a treatmentfluid, as described herein. Suitable polysaccharides for forming thehydrocolloid base fluids may include, but are not limited to, guar gums(e.g., hydroxyethyl guar, hydroxypropyl guar, carboxymethyl guar,carboxymethylhydroxyethyl guar, and carboxymethylhydroxypropyl guar(“CMHPG”)), cellulose derivatives (e.g., hydroxyethyl cellulose,carboxyethylcellulose, carboxymethylcellulose, andcarboxymethylhydroxyethylcellulose), xanthan, scleroglucan,succinoglycan, diutan, any in combination with a salt (e.g., sodiumchloride, calcium chloride, calcium bromide, zinc bromide, potassiumcarbonate, sodium formate, potassium formate, cesium formate, sodiumacetate, potassium acetate, calcium acetate, ammonium acetate, ammoniumchloride, ammonium bromide, sodium nitrate, potassium nitrate, ammoniumnitrate, ammonium sulfate, calcium nitrate, sodium carbonate, andpotassium carbonate), and the like, and any combination thereof.

The gelling agent (first, second, or any additional gelling agents) foruse in the various fluids described herein may be any gelling agentpreviously described herein. In some instances the gelling agent may beincluded in the gelled fluid and particulate slurry in an amountdifferent than that provided above with reference to the AA treatmentfluids because the gelled fluid and the particulate slurry, as discussedabove, may be particularly concentrated to allow the AA thereafterdilute the base fluid included therein and form an operatingparticulate-containing treatment fluid. That is, the finalparticulate-containing treatment fluid described above may have thegelling agent present therein in an amount described above withreference to the AA treatment fluid after it has been diluted with theAA.

The amount of gelling agent present in the gelled fluid or particulateslurry described herein may be dependent on the type of base fluidselected. When the base fluid selected is an aqueous base fluid, thegelling agent may be included in the gelled fluid (as well as theparticulate slurry), as described above, in an amount in the range offrom a lower limit of about 10 pounds per 1000 gallons (lb/Mgal), 12.5lb/Mgal, 15 lb/Mgal, 17.5 lb/Mgal, 20 lb/Mgal, 22.5 lb/Mgal, 25 lb/Mgal,27.5 lb/Mgal, 30 lb/Mgal, 32.5 lb/Mgal, 35 lb/Mgal, 37.5 lb/Mgal, and 40lb/Mgal to an upper limit of about 80 lb/Mgal, 75.5 lb/Mgal, 75 lb/Mgal,72.5 lb/Mgal, 70 lb/Mgal, 67.5 lb/Mgal, 65 lb/Mgal, 62.5 lb/Mgal, 60lb/Mgal, 57.5 lb/Mgal, 55 lb/Mgal, 52.5 lb/Mgal, 50 lb/Mgal, 47.5lb/Mgal, 45 lb/Mgal, 42.5 lb/Mgal, and 40 lb/Mgal, encompassing anyvalue and subset therebetween. When the base fluid selected is an oilbase fluid, the gelling agent may be included in the gelled fluid (aswell as the particulate slurry), as described above, in an amount in therange of from a lower limit of about 3 gallons per 1000 gallons(gal/Mgal, 4 gal/Mgal, 5 gal/Mgal, 6 gal/Mgal, 7 gal/Mgal, 8 gal/Mgal, 9gal/Mgal, and 10 gal/Mgal to an upper limit of about 20 gal/Mgal, 19gal/Mgal, 18 gal/Mgal, 17 gal/Mgal, 16 gal/Mgal, 15 gal/Mgal, 14gal/Mgal, 13 gal/Mgal, 12 gal/Mgal, 11 gal/Mgal, and 10 gal/Mgal of thebase fluid, encompassing any value and subset therebetween. When thebase fluid selected is a solvent base fluid, the gelling agent may beincluded in the gelled fluid (as well as the particulate slurry), asdescribed above, in an amount in the range of from a lower limit ofabout 20 lb/Mgal, 25 lb/Mgal, 30 lb/Mgal, 35 lb/Mgal, 40 lb/Mgal, 45lb/Mgal, 50 lb/Mgal, 55 lb/Mgal, and 60 lb/Mgal to an upper limit ofabout 100 lb/Mgal, 95 lb/Mgal, 90 lb/Mgal, 85 lb/Mgal, 80 lb/Mgal, 75lb/Mgal, 70 lb/Mgal, 65 lb/Mgal, and 60 lb/Mgal by volume of the basefluid, encompassing any value and subset therebetween. When the basefluid selected is a viscoelastic base fluid, the gelling agent may beincluded in the gelled fluid (as well as the particulate slurry), asdescribed above, in an amount in the range of from a lower limit ofabout 1%, 2%, 3%, 4%, 5%, 6%, 7%, and 8% to an upper limit of about 15%,14%, 13%, 12%, 11%, 10%, 9%, and 8% by volume of the base fluid,encompassing any value and subset therebetween. When the base fluidselected is a hydrocolloid base fluid, the gelling agent may be includedin the gelled fluid (as well as the particulate slurry), as describedabove, in an amount in the range of from a lower limit of about 0.5lb/Mgal, 1 lb/Mgal, 10 lb/Mgal, 20 lb/Mgal, 30 lb/Mgal, 40 lb/Mgal, and50 lb/Mgal to an upper limit of about 100 lb/Mgal, 90 lb/Mgal, 80lb/Mgal, 70 lb/Mgal, 60 lb/Mgal, and 50 lb/Mgal of the base fluid,encompassing any value and subset therebetween.

The particulates for use in the methods described herein for introducingthe treatment fluids comprising AA to a downhole location may includeany particulates for use in a subterranean formation operation (e.g.,proppant particulates, gravel particulates, and the like, and anycombination thereof). In some instances, the particulates may be of amaterial capable of withstanding fracture closing pressures. In someembodiments, the particulates may be a natural or man-made material suchas, for example, silica, alumina, fumed carbon, carbon black, graphite,mica, titanium dioxide, meta-silicate, calcium silicate, kaolin, talc,zirconia, boron, fly ash, crushed walnut, and the like, and anycombination thereof.

The particulates may be of any size and shape combination suitable forthe particular subterranean formation operation in which they are beingused (e.g., a fracturing operation). Generally, where the chosenparticulate is substantially spherical, suitable particulates may havean average particle size distribution in the range of from a lower limitof about 100 μm, 150 μm, 200 μm, 250 μm, 300 μm, 350 μm, 400 μm, 450 μm,500 μm, 550 μm, 600 μm, 650 μm, 700 μm, and 750 μm to an upper limit ofabout 1200 μm, 1150 μm, 1100 μm, 1050 μm, 1000 μm, 950 μm, 900 μm, 850μm, 800 μm, and 750 μm, encompassing any value and subset therebetween.In other embodiments, the average particle size distribution of theparticulates may be greater than about 1250 μm, 1300 μm, 1350 μm, 1400μm, 1450 μm, 1500 μm, or even larger, encompassing any value and subsettherebetween. In some embodiments of the present disclosure, theparticulates may have a size in the range of from about 2 to about 140mesh, U.S. Sieve Series.

In some embodiments, it may be desirable to use substantiallynon-spherical particulates. Suitable substantially non-sphericalparticulates may be cubic, polygonal, fibrous, or any othernon-spherical shape. Such substantially non-spherical particulates maybe, for example, cubic-shaped, rectangular-shaped, rod-shaped,ellipse-shaped, cone-shaped, pyramid-shaped, cylinder-shaped, and thelike, and any combination thereof. That is, in embodiments wherein theparticulates are substantially non-spherical, the aspect ratio of thematerial may range such that the material is fibrous to such that it iscubic, octagonal, or any other configuration. Substantiallynon-spherical particulates are generally sized such that the longestaxis is from about 0.02 inches (“in”), 0.03 in, 0.04 in, 0.05 in, 0.06in, 0.07 in, 0.08 in, 0.09 in, 0.1 in, 0.11 in, 0.12 in, 0.13 in, 0.14in, and 0.15 in to an upper limit of about 0.3 in, 0.29 in, 0.28 in,0.27 in, 0.26 in, 0.25 in, 0.24 in, 0.23 in, 0.22 in, 0.21 in, 0.2 in,0.19 in, 0.18 in, 1.17 in, 0.16 in, and 0.15 in length, encompassing anyvalue and subset therebetween. In other embodiments, the longest axis isfrom about 0.05 inches to about 0.2 inches in length. In one embodiment,the substantially non-spherical particulates may be cylindrical and havean aspect ratio of about 1.5 to about 1, and about 0.08 inches indiameter and about 0.12 inches in length. In another embodiment, thesubstantially non-spherical particulates may be cubic having sides ofabout 0.08 inches in length. The use of substantially non-sphericalparticulates may be desirable in some embodiments because, among otherthings, they may provide a lower rate of settling when slurried into afluid, or may be better suited for placement in preexisting and/or newfractures in a subterranean formation.

In some embodiments, the particulates may be present in the gelled fluid(as well as the particulate slurry) described herein in an amount in therange of a lower limit of about 18%, 20%, 22%, 24%, 26%, 28%, 30%, 32%,34%, 36%, 38%, 40%, and 42% to an upper limit of about 65%, 62%, 60%,58%, 56%, 54%, 52%, 50%, 48%, 46%, 44%, and 42%, encompassing any valueand subset therebetween.

The AA may be added to the gelled fluid or the particulate slurrydescribed herein to form the particulate-containing treatment fluidcomprising AA and to dilute the gelled fluid or the particulate slurry(also gelled) to an appropriate amount for use in a particularsubterranean formation operation. In some embodiments, the AA may beintroduced into the gelled fluid or the particulate slurry to form theparticulate-containing treatment fluid having a final particulateconcentration in the range of a lower limit of about 0.1%, 0.5%, 1%, 2%,4%, 6%, 8%, 10%, 12%, 14%, 16%, 18%, 20%, 22%, and 24% to an upper limitof about 48%, 46%, 44%, 42%, 40%, 38%, 36%, 34%, 32%, 30%, 28%, 26%, and24% by volume of the particulate-containing treatment fluid,encompassing any value and subset therebetween.

It is to be recognized that the disclosed fluids described herein (thosecomprising AA) may also directly or indirectly affect various downholeequipment and tools that may come into contact with the fluids duringoperation. Such equipment and tools may include, but are not limited to,wellbore casing, wellbore liner, completion string, insert strings,drill string, coiled tubing, slickline, wireline, drill pipe, drillcollars, mud motors, downhole motors and/or pumps, surface-mountedmotors and/or pumps, centralizers, turbolizers, scratchers, floats(e.g., shoes, collars, valves, etc.), logging tools and relatedtelemetry equipment, actuators (e.g., electromechanical devices,hydromechanical devices, etc.), sliding sleeves, production sleeves,plugs, screens, filters, flow control devices (e.g., inflow controldevices, autonomous inflow control devices, outflow control devices,etc.), couplings (e.g., electro-hydraulic wet connect, dry connect,inductive coupler, etc.), control lines (e.g., electrical, fiber optic,hydraulic, etc.), surveillance lines, drill bits and reamers, sensors ordistributed sensors, downhole heat exchangers, valves and correspondingactuation devices, tool seals, packers, cement plugs, bridge plugs, andother wellbore isolation devices, or components, and the like. Any ofthese components may be included in the systems generally describedabove and depicted in FIG. 1.

Embodiments disclosed herein include:

Embodiment A: A method comprising: preparing a treatment fluidcomprising a bulk amount of anhydrous ammonia, wherein the anhydrousammonia is present in an amount greater than about 10% by weight of aliquid portion of the treatment fluid, and wherein the anhydrous ammoniais in a phase selected from the group consisting of a liquid phase, agaseous phase, supercritical phase, and any combination thereof; andintroducing the treatment fluid into a subterranean formation.

Embodiment A may have one or more of the following additional elementsin any combination:

Element A1: Wherein the anhydrous ammonia is in the liquid phase or thesupercritical phase, and wherein the treatment fluid further comprises agelling agent, thereby forming gelled anhydrous ammonia treatment fluid.

Element A2: Wherein the anhydrous ammonia is in the liquid phase or thesupercritical phase, and wherein the treatment fluid further comprises agelling agent, thereby forming gelled anhydrous ammonia treatment fluid,and wherein the gelling agent is a colloidal clay.

Element A3: Further comprising introducing the treatment fluid into thesubterranean formation at a rate and pressure sufficient to create orenhance at least one fracture therein.

Element A4: Further comprising performing a subterranean formationoperation selected from the group consisting of a drilling operation, astimulation operation, an acidizing operation, an acid-fracturingoperation, a sand control operation, a fracturing operation, afrac-packing operation, a gravel-packing operation, a productionoperation, a remedial operation, a gas hydrate removal operation, anenhanced oil recovery operation, an injection operation, a pipelineoperation, a remedial operation, a formation damage reduction operation,a cementing operation, and any combination thereof.

Element A5: Wherein the subterranean formation has a temperature greaterthan 132.4° C. and pressure greater than 112.8 bar, such that theanhydrous ammonia is a supercritical fluid in the subterraneanformation.

Element A6: Wherein the subterranean formation comprises a carbonateselected from the group consisting of an alkali carbonate, analkai-earth carbonate, a transition metal carbonate, and any combinationthereof, and further comprising at least partially solubilizing thecarbonate with the anhydrous ammonia.

Element A7: Wherein the subterranean formation comprises a heavyaromatic compound, and further comprising at least partiallyammonolyzing the heavy aromatic compound with the anhydrous ammonia,thereby forming at least one wormhole in the subterranean formation.

Element A8: Wherein the subterranean formation comprises connate water,and further comprising contacting the anhydrous ammonia with the connatewater to increase a temperature of the subterranean formation.

Element A9: Further comprising etching microfractures in thesubterranean formation with the anhydrous ammonia.

Element A10: Further comprising recovering at least a portion of thetreatment fluid from the subterranean formation, and recycling theanhydrous ammonia recovered from the subterranean formation.

Element A11: Further comprising at least partially inhibiting formationof a gas hydrate in the subterranean formation.

Element A12: Further comprising a tubular extending into a wellbore inthe subterranean formation, and a pump fluidly coupled to the tubular,wherein the step of introducing the treatment fluid into thesubterranean formation comprises introducing the treatment fluid throughthe tubular.

By way of non-limiting example, exemplary combinations applicable to Ainclude: A with A1, A4, and A5; A with A2, A6, A8, and A12; A with A1,A2, A3, A4, A5, A6, A7, A8, A9, A10, A11, and A12; A with A3, A7, andA10; A with A0, A11, and A12, and the like.

Embodiment B: A method comprising: pre-treating a pipeline conduit witha treatment fluid, the treatment fluid comprising a bulk amount ofanhydrous ammonia, wherein the anhydrous ammonia is present in an amountgreater than about 10% by weight of a liquid portion of the treatmentfluid, and wherein the anhydrous ammonia in a phase selected from thegroup consisting of a liquid phase, a gaseous phase, supercriticalphase, and any combination thereof; and flowing a hydrocarbon throughthe pre-treated pipeline conduit.

Embodiment B may have one or more of the following additional elementsin any combination:

Element B1: Wherein the anhydrous ammonia is a supercritical fluid.

Element B2: Further comprising at least partially inhibiting theformation of a gas hydrate by pre-treating the pipeline conduit with thetreatment fluid.

Element B3: Wherein the anhydrous ammonia is in the liquid phase or thesupercritical phase, and wherein the treatment fluid further comprises agelling agent, thereby forming gelled anhydrous ammonia treatment fluid.

Element B4: Wherein the anhydrous ammonia is in the liquid phase or thesupercritical phase, and wherein the treatment fluid further comprises agelling agent, thereby forming gelled anhydrous ammonia treatment fluid,and wherein the gelling agent is a colloidal clay.

By way of non-limiting example, exemplary combinations applicable to Binclude: B with B1 and B2; B with B1 and B3; B with B1 and B4; B with B2and B3; B with B2 and B4; B with B3 and B4; B with B1, B2, and B3; Bwith B1, B3, and B4; B with B2, B3, and B4; B with B1, B2, B3, and B4;and the like.

Embodiment C: A treatment fluid comprising: anhydrous ammonia, whereinthe anhydrous ammonia is present in an amount greater than about 10% byweight of a liquid portion of the treatment fluid, and wherein theanhydrous ammonia in a phase selected from the group consisting of aliquid phase, a gaseous phase, and any combination thereof; and anoilfield additive selected from the group consisting of a gelling agent,a salt, a weighting agent, an inert solid, a fluid loss control agent,an emulsifier, a dispersion aid, a corrosion inhibitor, an emulsionthinner, an emulsion thickener, a surfactant, a particulate, a proppant,a gravel particulate, a lost circulation material, a foaming agent, agas, a pH control additive, a breaker, a biocide, a crosslinker, astabilizer, a chelating agent, a scale inhibitor, a gas hydrateinhibitor, a mutual solvent, an oxidizer, a reducer, a friction reducer,a clay stabilizing agent, a defoaming agent, and any combinationthereof.

Embodiment C may have one or more of the following additional elementsin any combination:

Element C1: Wherein the anhydrous ammonia is in the liquid phase or thesupercritical phase, and wherein the gelling agent is a colloidal clay,thereby forming gelled anhydrous ammonia treatment fluid.

Element C2: Wherein the anhydrous ammonia is a supercritical fluid.

Element C3: Wherein the treatment fluid further comprises a base fluidselected from the group consisting of an aqueous base fluid, an oil basefluid, a solvent base fluid, a viscoelastic base fluid, a hydrocolloidbase fluid, and any combination thereof.

By way of non-limiting example, exemplary combinations applicable to Cinclude: C with C1 and C2; C with C1 and C3; C with C2 and C3; C withC1, C2, and C3; and the like.

Embodiment D: A method comprising: preparing a gelled fluid comprising abase fluid, a first gelling agent, and particulates; introducing thegelled fluid into a process stream, the process stream in fluidcommunication with a subterranean formation; introducing anhydrousammonia into the gelled fluid at a downstream location in the processstream, thereby forming a particulate-containing treatment fluid; andintroducing the particulate-containing treatment fluid into thesubterranean formation from the process stream and through the wellhead.

Embodiment D may have one or more of the following additional elementsin any combination:

Element D1: Wherein the base fluid is selected from the group consistingof an aqueous base fluid, an oil base fluid, a solvent base fluid, aviscoelastic base fluid, a hydrocolloid base fluid, and any combinationthereof.

Element D2: Wherein the particulates are present in the gelled fluid inan amount in the range of from about 18% by volume of the gelled fluidto about 65% by volume of the gelled fluid.

Element D3: Wherein the anhydrous ammonia is introduced into the gelledfluid in an amount to achieve a final particulate concentration in theparticulate-containing treatment fluid in an amount in the range of fromabout 0.1% to about 48% by volume of the particulate-containingtreatment fluid.

Element D4: Wherein the anhydrous ammonia is in a phase selected fromthe group consisting of a liquid phase, a gaseous phase, and anycombination thereof.

Element D5: Wherein the process stream further comprises a pump in fluidcommunication therewith at an upstream location from the subterraneanformation, and the downstream location in the process stream forintroducing the anhydrous ammonia is upstream of the pump.

Element D6: Wherein the process stream further comprises a pump in fluidcommunication therewith at an upstream location from the subterraneanformation, and the downstream location in the process stream forintroducing the anhydrous ammonia is upstream of the pump, and whereinthe pump is a high pressure pump.

Element D7: Wherein a fluid selected from the group consisting of thegelled fluid, the particulate-containing treatment fluid, and anycombination thereof further comprises an oilfield additive selected fromthe group consisting of a second gelling agent, a salt, a weightingagent, an inert solid, a fluid loss control agent, an emulsifier, adispersion aid, a corrosion inhibitor, an emulsion thinner, an emulsionthickener, a surfactant, a lost circulation material, a foaming agent, agas, a pH control additive, a breaker, a biocide, a crosslinker, astabilizer, a chelating agent, a scale inhibitor, a gas hydrateinhibitor, a mutual solvent, an oxidizer, a reducer, a friction reducer,a clay stabilizing agent, and any combination thereof.

Element D8: Wherein a fluid selected from the group consisting of thegelled fluid, the particulate-containing treatment fluid, and anycombination thereof further comprises an oilfield additive added theretoby introducing the oilfield additive into the process stream, theoilfield additive selected from the group consisting of a second gellingagent, a salt, a weighting agent, an inert solid, a fluid loss controlagent, an emulsifier, a dispersion aid, a corrosion inhibitor, anemulsion thinner, an emulsion thickener, a surfactant, a lostcirculation material, a foaming agent, a gas, a pH control additive, abreaker, a biocide, a crosslinker, a stabilizer, a chelating agent, ascale inhibitor, a gas hydrate inhibitor, a mutual solvent, an oxidizer,a reducer, a friction reducer, a clay stabilizing agent, and anycombination thereof.

By way of non-limiting example, exemplary combinations applicable to Dinclude: D with D1, D2, and D8; D with D3, D5, D6, and D8; D with D withD4 and D7; D with D3 and D8; D with D1, D3, D4, and D8; and the like.

Embodiment E: A method comprising: preparing a gelled fluid comprising afirst base fluid and a first gelling agent; introducing the gelled fluidinto a process stream, the process stream in fluid communication with asubterranean formation; introducing particulates into the gelled fluidat a first downstream location in the process stream, thereby forming aparticulate slurry; introducing anhydrous ammonia into the particulateslurry at a second downstream location in the process stream, therebyforming a particulate-containing treatment fluid, wherein the seconddownstream location is downstream of the first downstream location; andintroducing the particulate-containing treatment fluid into thesubterranean formation from the process stream.

Embodiment E may have one or more of the following additional elementsin any combination:

Element E1: Wherein the base fluid is selected from the group consistingof an aqueous base fluid, an oil base fluid, a solvent base fluid, aviscoelastic base fluid, a hydrocolloid base fluid, and any combinationthereof.

Element E2: Wherein the step of introducing the particulates into thegelled fluid at the first downstream location in the process stream, andthe step of introducing the anhydrous ammonia into the particulateslurry at a second downstream location in the process stream, areperformed either sequentially in time or simultaneously in time.

Element E3: Wherein the particulates are introduced into the gelledfluid in an amount in the range of from about 18% by volume of thegelled fluid to about 65% by volume of the gelled fluid.

Element E4: Wherein the particulates are introduced into the gelledfluid in a gelled particulate slurry comprising a second base fluid anda second gelling agent.

Element E5: Wherein the anhydrous ammonia is introduced into theparticulate slurry in an amount to achieve a final particulateconcentration in the particulate-containing treatment fluid in an amountin the range of from about 0.1% to about 48% by volume of theparticulate-containing treatment fluid.

Element E6: Wherein the anhydrous ammonia is in a phase selected fromthe group consisting of a liquid phase, a gaseous phase, and anycombination thereof.

Element E7: Wherein the process stream further comprises a pump in fluidcommunication therewith at an upstream location from the subterraneanformation, and the second downstream location in the process stream forintroducing the anhydrous ammonia is upstream of the pump.

Element E8: Wherein the process stream further comprises a pump in fluidcommunication therewith at an upstream location from the subterraneanformation, and the second downstream location in the process stream forintroducing the anhydrous ammonia is upstream of the pump, and whereinthe pump is a high pressure pump.

Element E9: Wherein a fluid selected from the group consisting of thegelled fluid, the particulate slurry, the particulate-containingtreatment fluid, and any combination thereof further comprises anoilfield additive selected from the group consisting of a second gellingagent, a salt, a weighting agent, an inert solid, a fluid loss controlagent, an emulsifier, a dispersion aid, a corrosion inhibitor, anemulsion thinner, an emulsion thickener, a surfactant, a lostcirculation material, a foaming agent, a gas, a pH control additive, abreaker, a biocide, a crosslinker, a stabilizer, a chelating agent, ascale inhibitor, a gas hydrate inhibitor, a mutual solvent, an oxidizer,a reducer, a friction reducer, a clay stabilizing agent, and anycombination thereof.

Element E10: Wherein a fluid selected from the group consisting of thegelled fluid, the particulate slurry, the particulate-containingtreatment fluid, and any combination thereof further comprises anoilfield additive added thereto by introducing the oilfield additiveinto the process stream, the oilfield additive selected from the groupconsisting of a second gelling agent, a salt, a weighting agent, aninert solid, a fluid loss control agent, an emulsifier, a dispersionaid, a corrosion inhibitor, an emulsion thinner, an emulsion thickener,a surfactant, a lost circulation material, a foaming agent, a gas, a pHcontrol additive, a breaker, a biocide, a crosslinker, a stabilizer, achelating agent, a scale inhibitor, a gas hydrate inhibitor, a mutualsolvent, an oxidizer, a reducer, a friction reducer, a clay stabilizingagent, and any combination thereof.

By way of non-limiting example, exemplary combinations applicable to Einclude: E with E1, E4, and E10; E with E2, E5, E6, and E9; E with E3,E8, and E10; E with E1, E2, E3, and E4; E with E5, E8, and E9; E with E7and E10; and the like.

Therefore, the embodiments disclosed herein are well adapted to attainthe ends and advantages mentioned as well as those that are inherenttherein. The particular embodiments disclosed above are illustrativeonly, as they may be modified and practiced in different but equivalentmanners apparent to those skilled in the art having the benefit of theteachings herein. Furthermore, no limitations are intended to thedetails of construction or design herein shown, other than as describedin the claims below. It is therefore evident that the particularillustrative embodiments disclosed above may be altered, combined, ormodified and all such variations are considered within the scope andspirit of the present disclosure. The embodiments illustrativelydisclosed herein suitably may be practiced in the absence of any elementthat is not specifically disclosed herein and/or any optional elementdisclosed herein. While compositions and methods are described in termsof “comprising,” “containing,” or “including” various components orsteps, the compositions and methods can also “consist essentially of” or“consist of” the various components and steps. All numbers and rangesdisclosed above may vary by some amount.

Whenever a numerical range with a lower limit and an upper limit isdisclosed, any number and any included range falling within the range isspecifically disclosed. In particular, every range of values (of theform, “from about a to about b,” or, equivalently, “from approximately ato b,” or, equivalently, “from approximately a-b”) disclosed herein isto be understood to set forth every number and range encompassed withinthe broader range of values. Also, the terms in the claims have theirplain, ordinary meaning unless otherwise explicitly and clearly definedby the patentee. Moreover, the indefinite articles “a” or “an,” as usedin the claims, are defined herein to mean one or more than one of theelement that it introduces.

The invention claimed is:
 1. A method comprising: preparing a gelledfluid comprising a base fluid, a first gelling agent, and particulates,the base fluid includes a viscoelastic base fluid, a hydrocolloid basefluid, or any combination thereof; introducing the gelled fluid into aprocess stream, the process stream in fluid communication with awellhead, wherein the wellhead is in fluid communication with asubterranean formation; introducing anhydrous ammonia into the gelledfluid at a downstream location in the process stream prior to thewellhead, thereby forming a particulate-containing treatment fluid; andintroducing the particulate-containing treatment fluid into thesubterranean formation from the process stream and through the wellhead.2. The method of claim 1, wherein the base fluid is further selectedfrom the group consisting of an aqueous base fluid, an oil base fluid, asolvent base fluid, and any combination thereof.
 3. The method of claim1, wherein in the step of preparing a gelled fluid, the particulates arepresent in the gelled fluid in an amount in the range of from about 18%by volume of the gelled fluid to about 65% by volume of the gelledfluid.
 4. The method of claim 1, wherein the anhydrous ammonia isintroduced into the gelled fluid in an amount to achieve a finalparticulate concentration in the particulate-containing treatment fluidin an amount in the range of from about 0.1% to about 48% by volume ofthe particulate-containing treatment fluid.
 5. The method of claim 1,wherein the anhydrous ammonia is in a phase selected from the groupconsisting of a liquid phase, a gaseous phase, and any combinationthereof.
 6. The method of claim 1, wherein the process stream furthercomprises a pump in fluid communication therewith at an upstreamlocation from the subterranean formation, and the downstream location inthe process stream for introducing the anhydrous ammonia is upstream ofthe pump.
 7. The method of claim 6, wherein the pump is a high pressurepump.
 8. The method of claim 1, wherein the gelled fluid or theparticulate-containing treatment fluid further comprises an oilfieldadditive selected from the group consisting of a second gelling agent, asalt, a weighting agent, an inert solid, a fluid loss control agent, anemulsifier, a dispersion aid, a corrosion inhibitor, an emulsionthinner, an emulsion thickener, a surfactant, a lost circulationmaterial, a foaming agent, a gas, a pH control additive, a breaker, abiocide, a crosslinker, a stabilizer, a chelating agent, a scaleinhibitor, a gas hydrate inhibitor, a mutual solvent, an oxidizer, areducer, a friction reducer, a clay stabilizing agent, and anycombination thereof.
 9. The method of claim 1, wherein the gelled fluidor the particulate-containing treatment fluid further comprises anoilfield additive added thereto by introducing the oilfield additiveinto the process stream, the oilfield additive selected from the groupconsisting of a second gelling agent, a salt, a weighting agent, aninert solid, a fluid loss control agent, an emulsifier, a dispersionaid, a corrosion inhibitor, an emulsion thinner, an emulsion thickener,a surfactant, a lost circulation material, a foaming agent, a gas, a pHcontrol additive, a breaker, a biocide, a crosslinker, a stabilizer, achelating agent, a scale inhibitor, a gas hydrate inhibitor, a mutualsolvent, an oxidizer, a reducer, a friction reducer, a clay stabilizingagent, and any combination thereof.